Offshore floating utility platform and tie-back system

ABSTRACT

The present invention relates to a system for producing hydrocarbons from remote subsea wells to a host production facility using a portable floating utility platform and tie-back system. The subject system comprises a floating utility platform positioned near a plurality of subsea wells; a plurality of control umbilicals connecting said platform to a well control system positioned near the wells and a pump and separation control system wherein the produced hydrocarbons flow from the well control system through a HIPPS to the pump and separation control system; and a host production platform equipped to receive the produced hydrocarbons from a reduced pressure export flowline that transports the hydrocarbons the entire tie-back length from the pump and separation control system to the host production platform. Optionally, the system can provide seawater injection capabilities as well as a single-track pigging.

RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application No.62/697,210 filed Jul. 12, 2018. The entire contents of the aboveapplication are hereby incorporated by reference as though fully setforth herein.

FIELD

The present invention relates to the field of subsea hydrocarbonproduction. More specifically, the present invention relates to a systemfor producing hydrocarbons from remote subsea wells to a host productionfacility using a portable floating utility platform and tie-back system.

BACKGROUND

With larger oil and gas discoveries becoming less common, especially inthe Gulf of Mexico, attention has turned to previously untapped, lesseconomically viable discoveries. However, with crude oil pricesremaining depressed, it is simply not economically feasible forcompanies to manufacture and deploy new production facilities to theseremote, smaller reservoirs, especially in deeper water. For example, thecost alone to develop a deep-water strategy, and then manufacture anddeploy the necessary infrastructure, can exceed a billion dollars andtake up to ten years. With stagnant oil prices below sixty dollars perbarrel, and these remote reservoirs estimated to yield less than 100 MMbarrels of equivalent (BOE) of crude oil, the economics do not justifysuch an investment.

This inherent problem has forced offshore production companies,especially in the Gulf of Mexico, to develop “tie back” systems thatutilize long umbilicals and subsea systems to connect these lesscommercially viable reservoirs to existing production platforms (or“host platforms”). However, current tie-back systems presently availablehave their own technical and commercial limitations. Current tie-backsystems comprise three essential elements: (i) a host productionplatform that (ii) utilizes a plurality of umbilicals to providenecessary well-control and subsea support, and (iii) at least oneflowline for transporting hydrocarbons from the well(s) to the hostplatform. A typical subsea development system consists of at least onesubsea production well or wells, a manifold (if there is more than onewell), pipeline end terminations (PLETS), and an umbilical terminationassembly, connected by flowlines, jumpers, flying leads and umbilicals.The capital cost and technical requirements for flow assurance in theseconventional tie-back systems have limited the tie-back distance toapproximately a twenty-five (25+/−) mile radius from the host facility,leaving several reservoirs out of reach from existing facilities. In theGulf of Mexico alone, there exists several additional, commerciallyviable remote discoveries, that remain untapped because of thelimitations associated with current tie-back systems.

Additionally, the Bureau of Safety and Environmental Enforcement (BSEE)has not been willing to allow long distance tie-back systems to utilizea high-integrity pressure protection system (HIPPS) as a safeguard toprevent over pressurization in flowlines. A HIPPS is installed in theflowline near the wellhead in order to monitor pressure in the flowline,and if needed, close off the flowline through a series of hydraulicallyactuated valves. A HIPPS generally consists of a plurality of sensingelements used to measure flowline pressure, a processor adapted tocompute the values from the sensing elements to determine whether theflowline is over pressurized, and if so, the processor will send ademand signal to the host platform through an umbilical to close thehydraulically actuated valves. However, BSEE has yet to approve a HIPPSfor a long distance conventional tie-back system due to the fact thatthe demand signal must travel up to twenty-five (25) miles from the wellto the host facility; the time delay between the signal demand andactual shut-off is too long and exposes flowlines to over pressurizationfor an unacceptable amount of time.

Without a HIPPS in place, BSEE requires every component of the systemfrom the wellhead to the host production facility, including allflowlines, be tested to withstand maximum shut-in reservoir pressure. Inthe Gulf of Mexico, reservoir pressures can reach 15,000 psi. Equippingconventional tie-back systems with piping that meets these standardssignificantly increases capital development costs, especially when thetie-back system is servicing multiple wells. With a HIPPS in place, BSEEwould allow for production flowlines to be rated for dramatically lowerpressures, thus reducing excess material costs, up to as much as 350%,as distances increase between the remote wells and the host facility.

Additionally, current tie-back systems are limited in their ability toprovide water injection (a.k.a waterflooding) treatments to thereservoir as a means to enhance hydrocarbon production. For offshoredevelopments, waterflooding involves drilling injection wells into thereservoir and introducing treated water into the reservoir to increasedepleted pressure in the reservoir, allowing for additional hydrocarbonsto be produced. As tie-back distances increase, the required controlumbilicals, power umbilicals, risers, and equipment to facilitate suchtreatments render this option less viable from an economics andtechnical standpoint.

Additionally, as tie-back distance increases for these systems andreservoir pressure is depleted, it becomes critical for the system toprovide power generation capabilities to subsea booster pumps near thewell in order to facilitate transportation of the hydrocarbons back tothe host facility. Like waterflooding, power for these booster pumps isprovided though umbilicals connected to the host facility. And insimilar fashion, when it comes to servicing more remote wells, anumbilical connection between the subsea pumping system and the hostfacility becomes less viable.

BRIEF SUMMARY OF THE INVENTION

It is the object of the present invention to overcome the economical andtechnical limitations in current tie-back systems by developing animproved system that still utilizes an existing host productionfacility, but greatly increases the tie-back length while simultaneouslyproviding a safer, more productive, and cost-efficient method forproducing hydrocarbons from these remote reservoirs.

In the preferred embodiment, the tie-back system comprises a floatingutility platform positioned near a plurality of subsea wells; aplurality of control umbilicals connecting said platform to a wellcontrol system positioned near the wells and a pump and separationcontrol system wherein the produced hydrocarbons flow from the wellcontrol system through a HIPPS to the pump and separation controlsystem; and a host production platform equipped to receive the producedhydrocarbons from a reduced pressure export flowline that transports thehydrocarbons the entire tie-back length from the pump and separationcontrol system to the host production platform. Although the preferredembodiment utilizes the HIPPS in tandem with a subsea pump andseparation control system, alternative embodiments may use one withoutthe other.

Optionally, the system further provides a more efficient and affordablemethod for pigging the export flowline. “Pigging” is a term used in theart to refer to a method of cleaning and inspecting the export flowlinethrough the process of deploying single unit “pigs” into the flowline.For existing tie-back systems, a pig launching station located on thehost facility is connected to the well control system via one highpressurized flow line and the pig receiving station would also belocated on the host production platform and connected to the second highpressure export flowline transporting the hydrocarbons to the hostfacility, such that a closed loop is formed. The pig launching stationwould launch a “pig” that would travel through the aforementioned loop,serving to unclog and clean any blockages in the export flowline. Unlikecurrent tie-back systems, the disclosed system does not require a closedloop for pigging capabilities. Rather, the floating utility platform maybe equipped with a pig launching station wherein pigs will be launcheddirectly into a low pressure export flowline via a WYE fitting or someother comparable fitting and received by the host production facility.

Optionally, the system further provides water flooding capabilitiesknown in the art to these remote reservoirs to enhance hydrocarbonproduction combined with power generation capabilities for subsea pumpsto export hydrocarbons from depleted reservoirs back to the hostfacility.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is schematic diagram of the preferred embodiment of the presentsystem.

FIG. 2 is schematic diagram of the preferred embodiment of the presentsystem showing a plurality of subsea wells interconnected by a wellcontrol system.

FIG. 3 is a schematic diagram for a High Integrity Pressure ProtectionSystem (HIPPS) incorporated into the preferred embodiment of the presentsystem.

FIG. 4 is a schematic diagram of the preferred embodiment of the presentsystem showing the subsea pump and separation control system.

FIG. 5 is a schematic diagram for a pigging system incorporated into thepreferred embodiment of the present system.

FIG. 6 is a schematic diagram for a seawater treatment and injectionsystem incorporated into the preferred embodiment of the present system.

DETAILED DESCRIPTION

Turning to FIG. 1, a schematic diagram of the preferred system is shown.The system comprises a host production platform 10 spaced apart from afloating utility platform 20 that is positioned near a plurality ofsubsea wellheads 110, and a network of subsea systems, including a wellcontrol system 25 (as shown in detail in FIG. 2) utilizing a HIPPS 35(as shown in detail in FIG. 3), a pump and separation control system (asshown in detail in FIG. 4), an optional pigging system 55 (shown in FIG.5), an optional seawater treatment and injection system 65 (shown inFIG. 6), and a plurality umbilicals used to connect the utility platform20 to the various subsea systems, as well as flowlines that are used totransport hydrocarbons from the well to the host production platform 10.The host production platform 10 is further equipped to receive thehydrocarbons via a fortified steel catenary riser (“SCR”) 30 adapted toreceive the hydrocarbons from the low-pressure export flowline 50.

Turning to FIGS. 1-2, the preferred system anticipates the floatingutility platform 20 may be positioned up to approximately one radialmile from any of the subsea wells 100 that are interconnected via thewell control system 25. Necessary power, chemicals, and well control areprovided to the well control system 25 via a first umbilical 70 from theutility platform 20. The first umbilical 70 terminates at a subseatermination unit 80 where a plurality of flying leads 90 provideutilities and control over each subsea tree 120 (positioned on top of awellhead 110), a subsea manifold 140 (if more than one well is beingserviced), and the HIPPS module 150. Although the figures demonstratethat the subsea termination unit 80 is raised above the sea floor, thiswas purely for ease in demonstrating the connections in the well controlsystem 25. For purposes of this application, the subsea termination unit80 is located on the sea floor. Assuming a plurality of wells 100 arebeing serviced, the crude oil from the wells 100 is transported from thewellheads 110 and trees 120, to the manifold 140 via complianthigh-pressure flowlines 130, commonly known as “jumpers” in the art. TheHIPPS module 150 may be incorporated into the manifold 140 or connectedto the manifold 140 by a high-pressure flowline 130.

Turning to FIG. 3, a HIPPS requires control equipment and powergeneration capabilities on the topside of the utility platform 20,including a HIPPS control panel, a hydraulic power unit, and anelectrical power unit (not shown). The utilities provided by the topsideequipment are connected to the subsea HIPPS module 150 via the firstumbilical 70, that terminates at the subsea termination unit 80, werepower is passed through to the connecting leads 90. The module 150comprises a plurality of pressure sensors 160 adapted to measure thepressure in the flowline 130, and a processor 170 adapted to performdiagnostics on the input pressure values and determine if a demandsignal should be sent to the shut-down valves 180 to preventoverpressurization. The fortified flowline 190 from the HIPPS module 150to the subsea pump and separation module 210 is rated to full reservoirshut-in pressure to account for any overpressurization caused by thedelay between the transmission of a demand signal and the shut-downvalves 180 being activated.

Turning to FIG. 4, the preferred system further comprises a subsea pumpand separation control system 45 that is connected to the utilityplatform 20 by a second umbilical 200 that provides power, controls, andhydraulics to a pump module 210 on the sea floor. At a minimum, the pumpmodule 210 comprises at least a single pump and an equivalent back-uppump that are regulated by valves and a control unit inside the pumpmodule. An example of a pump module known in the art that may beincorporated into the system is the helicoaxial multiphase pump module,or any type of similar module. According to BSEE standards, thefortified pipeline 190 transporting hydrocarbons from the well controlsystem 25 to the pump module 210, or if using a HIPPS, from the HIPPSmodule 150 to the pump module 210, must be rated to withstand fullreservoir shut-in pressure. The preferred system anticipates the pumpmodule 210 may be positioned up to approximately one radial mile fromthe HIPPS module 150 or well control system 25. As shown in FIG. 1, thesubsea pump module 210 is positioned on the sea floor approximatelybeneath the floating utility platform 20. When activated, the boosterpumps within the pump module 210 function to reduce backpressure on thereservoir. Back pressure is related to the resistance to flow downstreamfrom the well to the host platform. For the subject system, the backpressure tells you how much pressure is needed to achieve a certainflowrate. By reducing backpressure in the flowline, a depleted reservoirpressure is sufficient to produce additional hydrocarbons from the welland transport those hydrocarbons over greater distances to the hostproduction platform 10. For the disclosed system, the use of a HIPPS intandem with the subsea pump and separation control system 45 allow notonly additional hydrocarbons to be produced from a remote well, but alsoallows those hydrocarbons to be transported up to a distance ofapproximately one hundred miles to the host production platform 10 via alower pressure compliant export flowline 50.

Turning to FIG. 5, as an additional option, the preferred system allowsthe incorporation of a single-track pigging system 55, as opposed to aclosed-loop system utilized in existing tie-back systems. The piggingsystem 55 comprises topside equipment on the utility platform 20,including at a minimum a pig launching unit, pigging pump, isolationvalve skid, and a hydraulic power unit (not shown). This equipmentallows a pig to be propelled from the pig launcher on the topside of theplatform 20 through a SCR 220 and into the low-pressure export pipeline50 via a Wye fitting 250, such as the piggable Wye fittings manufacturedby Oceaneering®, located inside the subsea pigging skid 230. The piggingskid 230 further comprises at least one actuator valve 240 that controlsthe access of a pig into the WYE fitting 250. The valve 240 can be openand closed by using a remote operated vehicle (ROV), or via the secondumbilical 200 if the valve is hydraulically actuated.

As a second option, the system may further comprise a seawater treatmentand injection system 65 to provide waterflooding capabilities to enhancehydrocarbon recovery from depleted wells. As seen in FIG. 6,waterflooding requires a separate pre-drilled injection well 270 that isspaced apart from the previously disclosed subsea systems and isconnected to the utility platform 20 via a water injection SCR 260. Theutility platform 20 is equipped with required topside equipment (notshown) known in the art that enables treated seawater to be pumpedthrough the injection SCR 260 and into the injection well 270. Ingeneral, topside seawater intake pumps will lift seawater to the topside; the water is then filtered through a coarse strainer andmicrofiltration skid. Next, the water is pumped through a sulfatereduction membrane to remove sulfate ions and a deaeration membrane toremove oxygen before being pressurized and pumped into the injection SCRby a plurality of injection pumps. This process is repeated as much andas often as necessary to replenish depleted pressure in the reservoir,allowing for additional hydrocarbons to be recovered.

For the purposes of promoting an understanding of the principles of theinvention, reference has been made to the preferred embodimentsillustrated in the drawings, and specific language has been used todescribe these embodiments. However, this specific language intends nolimitation of the scope of the invention, and the invention should beconstrued to encompass all embodiments that would normally occur to oneof ordinary skill in the art. The particular implementations shown anddescribed herein are illustrative examples of the invention and are notintended to otherwise limit the scope of the invention in any way. Forthe sake of brevity, conventional aspects of the method (and componentsof the individual operating components of the method) may not bedescribed in detail. Furthermore, the connecting lines, or connectorsshown in the various figures presented are intended to representexemplary functional relationships and/or physical or logical couplingsbetween the various elements. It should be noted that many alternativeor additional functional relationships, physical connections or logicalconnections might be present in a practical device. Moreover, no item orcomponent is essential to the practice of the invention unless theelement is specifically described as “essential” or “critical”. Numerousmodifications and adaptations will be readily apparent to those skilledin this art without departing from the spirit and scope of the presentinvention.

What is claimed is:
 1. A system for producing hydrocarbons from a subseawell, comprising: a. a floating utility platform; b. a host productionplatform operable to receive hydrocarbons; c. a well control system; d.a HIPPS; e. a pump and separation control system; f. a first umbilicaland a second umbilical; and g. a reduced pressure export flowline;wherein the first umbilical connects the utility platform to the wellcontrol system and the second umbilical connects the utility platform tothe pump and separation control system; wherein hydrocarbons areproduced from the subsea wells into the well control system; wherein theproduced hydrocarbons are exported from the well control system, througha HIPPS, to the pump and separation control system before being exportedto the host production platform via the reduced pressure exportflowline.
 2. The system of claim 1 wherein the well control systemconnects to a plurality of wells.
 3. The system of claim 1 wherein thepump and separation control system is positioned up to one mile from thewell control system.
 4. The system of claim 1 wherein the hostproduction platform is position up to one hundred miles away from thepump and separation control system.
 5. The system of claim 1 furthercomprising a single-track pigging system, wherein one end of the systemis connected to the utility platform and the other end is connected to areduced pressure export flowline.
 6. The system of claim 1 furthercomprising a seawater treatment and injection system that is connectedto the utility platform via a SCR on one end and the other end isconnected to an injection well, wherein treated seawater is pumped fromthe utility platform through the SCR and into the injection well.
 7. Asystem for producing hydrocarbons from a subsea well, comprising: a. afloating utility platform; b. a host production platform operable toreceive hydrocarbons; c. a well control system; d. a pump and separationcontrol system; and e. a first umbilical and a second umbilical; whereinthe first umbilical connects the utility platform to the well controlsystem and the second umbilical connects the utility platform to thepump and separation control system; wherein hydrocarbons are producedfrom the subsea wells into the well control system; wherein the producedhydrocarbons are exported from the well control system to the pump andseparation control system before being exported to the host productionplatform via a compliant export flowline.
 8. The system of claim 7wherein the well control system connects to a plurality of wells.
 9. Thesystem of claim 7 wherein the pump and separation control system ispositioned up to one mile from the well control system.
 10. The systemof claim 7 wherein the host production platform is position up to onehundred miles away from the pump and separation control system.
 11. Thesystem of claim 7 further comprising a single-track pigging system,wherein one end of the system is connected to the utility platform andthe other end is connected to the compliant export flowline.
 12. Thesystem of claim 7 further comprising a seawater treatment and injectionsystem that is connected to the utility platform via a SCR on one endand the other end is connected to an injection well; wherein treatedseawater is pumped from the utility platform through the SCR and intothe injection well.
 13. A system for producing hydrocarbons from asubsea well, comprising: a. a floating utility platform; b. a hostproduction platform operable to receive hydrocarbons; c. a pump andseparation control system; d. an umbilical that connects the utilityplatform to the pump and separation control system; wherein the pump andseparation control system is operable to export produced hydrocarbonsfrom existing wells to the host production platform via a compliantexport flowline.
 14. The system of claim 13 wherein the host productionplatform is position up to one hundred miles away from the pump andseparation control system.
 15. A system for producing hydrocarbons froma subsea well, comprising: a. a floating utility platform; b. a hostproduction platform operable to receive hydrocarbons; c. a well controlsystem; and d. a seawater treatment and injection system; wherein anumbilical connects the utility platform to the well control system;wherein the produced hydrocarbons are exported from the well controlsystem to the host production platform via a compliant export flowline;wherein the seawater treatment and injection system is connected to theutility platform via a SCR on one end and the other end is connected toan injection well that is spaced apart from the well control system,wherein treated seawater is pumped from the utility platform through theSCR and into the injection well.
 16. The system of claim 15 wherein thewell control system is connected to a plurality of wells.
 17. The systemof claim 15 further comprising a single-track pigging system, whereinone end of the system is connected to the utility platform and the otherend is connected to the reduced pressure export flowline.
 18. A methodfor producing hydrocarbons from a subsea well, comprising: a. providinga floating platform positioned in proximity to a subsea well; b.providing a well control system; c. providing a subsea HIPPS; d.providing a pump and separation control system; e. providing a pluralityof control umbilicals connecting said utility platform to the wellcontrol system, HIPPS, and pump and separation control system; f.providing a host production platform operable to receive the producedhydrocarbons; g. providing a reduced pressure export flowline; h.producing the hydrocarbons from the well and transporting thehydrocarbons through a compliant high-pressure flowline connecting thewell control system, the HIPPS, and the pump and separation controlsystem, and i. pumping the hydrocarbons through the reduced pressureexport flowline to the host production platform.
 19. The methodaccording to claim 18, further comprising the step of controlling thepressure in the reduced pressure export flowline connecting the pump andseparation control system to the host production platform through aplurality of subsea pumps.
 20. The method of claim 18, furthercomprising the step of transporting the hydrocarbons a distance of up toone hundred miles from the pump and separation control system to thehost production platform.
 21. The method of claim 18, further comprisingthe step of injecting treated seawater into the well reservoir byproviding a seawater treatment and injection system that is connected tothe utility platform via a SCR on one end and the other end is connectedto an injection well, wherein treated seawater is pumped from theutility platform through the SCR and into the injection well.
 22. Themethod of claim 18, further comprising the step of pigging the reducedpressure export flowline by providing a single-track pigging system thatis connected to the utility platform on one end and the other end isconnected to the reduced export flowline.